Subterranean formations have tremendous pressures exerted upon them and it is these pressures that can cause major differences between clay/shales and the behaviour of said clay/shales found at different depths, where hydrocarbon production typically predominates. The amount of pressure applied to the clay which results in the thickness of clay platelets is dictated by the amount of overburden that exists above the zone of interest, i.e. the depth of the pay zone in the well.
A single smectite platelet is composed of a central alumina or magnesium layer joined to silica layers. The particle is typically about one nanometer in thickness and up to several nanometers in width. In general, the charge on the molecules that make up the layers of clay platelets line up in such a way so as to have a face of the platelet negatively charged and the edges having a slight positive charge. The overall charge of a clay platelet however is negative.
Charges on the clay platelets permit interaction with dissolved mineral ions in aqueous fluids, both native and non-native to the formation. The net negative charge on a platelet is typically balanced mainly by sodium ions, although other inorganic cations may also be present in minor amounts. The cations, or charge-balancing ions, associate with the platelet faces and are termed “exchangeable” as they can be readily substituted with other cations when presented to the clay platelets. Each macroscopic clay particle is comprised of many thousands of sandwiched clay platelets, each having exchangeable cations and a layer of water therebetween.
When clay and water are mixed, water penetrates between the platelets, forcing them further apart. The cations present at the platelet faces begin to diffuse away from platelet faces. Further, the amount of water contained within the platelets is dependant upon the pressure under which the clay is located, typically the depth of the clay deposit in the subterranean formation.
Typically, freshly deposited clay sediments have a relatively high water content, solids comprising only about 50% of the total volume. However, much of this fluid fills the pore spaces between the particles and is squeezed out rapidly during the initial stages of burial. Below about 500 m, all that remains of the fluid is a few molecular thicknesses of interlayer water, bound to the internal clay surfaces and the cations associated therewith. The interlayer water is expelled upon deeper burial, generally by a combination of temperature and clay diagenesis. Very little fluid remains in clay sediments below about 10 km.
In a typical petroleum-rich sedimentary basin, compacting stress increases at a rate of about 1.5×107 Pa (150 bar) per kilometer, which corresponds to geostatic pressure generated by the overlying sediments and their fluids. In addition, the geothermal temperature gradient is typically about 30° C. per kilometer. These features of buried formations are generally thought to promote differences between the observed behaviour of clay in various oil-producing subterranean formations. Applicant is aware that at least some literature (N. T. Skipper, G. D. Williams, A. V. C. de Siqueira, C. Lobban (University College, London) A. K. Soper, R. Done, J. Dreyer, R. Humphries (ISIS)) indicates that it has been determined through experimentation that the layer spacing in vermiculite clays immersed in water is a function of burial depth. It has been shown that sodium vermiculite collapses from a two-layer hydrate (14.96 Å) to a one-layer hydrate (12.35 Å) at a depth of about 6 km. The reversible dehydration observed corresponds to a loss of one layer of water molecules from between the clay platelets. Thus, it is extremely important to measure the depths at which water is ejected from swelling clays in this way for example, to understand and predict the primary migration of oil and natural gas therein. Primary migration is the process whereby hydrocarbons move from the sedimentary source rocks, in which they were formed, to higher permeability reservoir rocks, from which they can now be extracted.
Production of petroleum hydrocarbons is often troubled by the presence of clays and other fines capable of migrating within the formation. Normally, these fines, including the clays, cause no obstruction of flow to a wellbore via the capillary system of the formation. When the fines are disturbed however, they may begin to migrate within the production stream and, too frequently, encounter constrictions in the capillary, where they bridge off the capillary and severely diminish the flow rate of hydrocarbons to the wellbore.
Further, the introduction of water foreign to the formation, such as introduced through drilling or production processes, has been shown to frequently disturb the fines in these clay-containing formations. The foreign water is often fresh or relatively fresh water compared to brine, which is native to the formation. The change in the nature of the water present may cause the fines to disperse or come loose from adhesion to capillary walls, usually resulting in the migration of the fines through the formation, where plugging can occur in smaller pore throats.
Sometimes the loss of permeability observed is due to clay swelling with the relatively fresh water, without migration. Most often however, clay swelling is accompanied by migration of fines. Non-swelling clays may also respond to the foreign water and begin to migrate. It is believed however that swelling clays are the major mechanism of formation damage due to loss of mobility of hydrocarbon fluids in the formation.
Clay hydration occurs by three mechanisms: surface hydration through bonding of water molecules to oxygen atoms on the surface of the clay platelets; ionic hydration through hydration of interlayer cations with surrounding shells of water molecules; and osmotic hydration which occurs in some clays after they are completely surface and ionically hydrated, usually at 100% humidity.
All clays experience hydration. Illite and smectite clays exhibit varying degrees of ionic hydration. Shale hydration, typically caused by surface adsorption hydration and osmotic absorption hydration, results in two distinctly different problems, one being swelling, which is expansion of the clays due to water uptake and the other being dispersion, which is the disintegration of the shale body due to water contact.
As shale includes non-clay minerals, such as quartz and feldspar, and is typically a heterogenous mixture of clays, a combination of hydration mechanisms may occur in the same piece of rock. For example, the non-clay minerals will not react, the chlorite, kaolinite, and illite clays will hydrate and create solids problems and the smectite clays will hydrate, swell, and react with ionic solutions.
Swelling clays, such as smectites and vermiculites, are layered minerals that are widespread in soils and sedimentary rocks. As previously described, they are made up of negatively charged mica-like sheets which are held together by charge-balancing, interlayer cations such as calcium, magnesium, or sodium. The cations have a strong affinity for polar solvents. For this reason the interlayer regions of smectites and vermiculites tend to expand readily in the presence of water and aqueous solutions. A great deal is known about clay hydration under ambient conditions. In contrast, however, there is little understanding of clay swelling and clay-water interactions under the conditions encountered in sedimentary basins and oilfields.
Drilling shales are susceptible to a variety of problems ranging from washout to complete hole collapse. Shales make up over 75% of the drilled formations and over 70-90% of the borehole problems are related to shale instability. In the past, oil-based muds (OBM) have been the preferred choice for drilling these argillaceous or clayey formations. The application of OBM has previously been justified on the basis of borehole stability, penetration rate, fluid loss, filter cake quality, lubricity, and temperature stability. More recently, mainly in the last decade, environmental regulations have restricted the use of diesel and mineral oil-based muds, synthetic and ester-based biodegradable invert emulsion drilling fluids.
Water-based muds (WBM) have therefore become attractive alternatives to emulsion systems, both from the cost and the environmental perspectives. Disadvantageously, however, clay-rich rocks, such as shales, tend to expand when in contact with water-based drilling fluids (WBDFs). The expansion of the clay-containing portions of the formation cause instability and collapse of the well-bore which typically costs the oil industry about $2 billion per annum. Current and conventional solutions to the problem include the use of environmentally unfriendly oil-based drilling fluids.
Further, many fluids which are introduced to the formation, such as acidizing fluids, fracturing fluids and the like are water-based or have a significant water content and thus add to the problems of clay swelling.
Historically, the oilfield industry has tried various methods for the control of clay swelling and migration in an effort to reduce the occurrence of formation damage caused by the introduction of foreign aqueous fluids into sensitive formations. It is generally thought that once damage as a result of swelling has occurred it is unlikely that any significant reversal of the damage is possible.
One concept that has been used is to convert the clay from a swelling form which contains sodium to a form comprising other cations which does not swell as much. For example, cations that form relatively non-swelling clays are potassium, calcium, ammonium and hydrogen ions. When a solution of these cations, mixed or individually, flows past a clay mineral, the cations readily replace the sodium ion present in the clay and the clay is transformed to a relatively non-swelling form. One such system is taught in Canadian patent 1,227,744 to Hopkins et al. (Mobil Corporation), wherein it was concluded that the use of acid, potassium, calcium, or ammonium ions to exchange sodium ion was successful in preventing damage to formations susceptible to plugging or disintegrating due to clays in their compositions.
Applicant believes however that the method taught by Hopkins et al and other methods of this type using simple cation exchange have been found to be only a temporary solution to the problem. Native produced brine inherent in the formation quickly re-introduces sodium ions to the clay and the cations which have been used to displace sodium are just as readily exchanged by sodium in the native brine. Thus, the formation becomes susceptible to swelling and migration once again.
Petroleum-bearing, shale/clay mineral zones are usually found at various depths in subterranean formations and each zone has a unique porosity and permeability in its native state. Thus, each zone can be expected to behave differently when exposed to non-native aqueous fluids. Prior art solutions to prevent each of these various clay types from swelling are different, the ability of the various inhibitors or stabilizing agents to migrate into the clay platelets being heavily influenced by the individual molecules molecular weight. Most conventional clay stabilizing agents work on the principle of substitution of sodium in the clay lattice with another cationic species. The cationic species is generally selected such that its radius of hydration is less than that of the sodium ion; resulting in reduced swelling when the clay comes in contact with a foreign fluid. As previously stated, however this type of clay stabilization is typically temporary because the small cations (either Potassium, Ammonium or Tetramethyl Ammonium Chloride (TMAC)), which have been used to replace the sodium cation, are themselves quickly replaced, once flow from the well is re-established.
Others in the prior art have taught methods and systems which are designed to overcome the problems of the impermanence of the solution using simple cation exchange. Some of the prior art proposed solutions include;
Canadian patent 1,097,904 to Anderson et al. which teaches the use of flax seed gum and up to 10,000 ppm of potassium or ammonium cations;
Canadian patent 2,492,797 to Stamatakis et al. which teaches the use of an acid salt of alkaline esters;
Canadian patent 1,092,575 to Rice et al. which teaches the use of aliphatic hydroxyacids with between 2-6 carbon atoms;
Canadian patent 2,106,778 to Thomas et al. which teaches the use of cationic allyl ammonium halide salts;
Canadian patent 1,103,008 to McLaughlin et al. which teaches the use of poly allyl ammonium halide salts;
Canadian patent 2,300,110 Craster et al. which teaches the use of polyols containing at least 1 nitrogen atom preferably from a diamine;
U.S. Pat. No. 5,771,971 to Horton et al. which teaches the use of primary diamine salt with a chain length of 8 or less;
U.S. Pat. No. 5,908,814 to Patel et al. which teaches the use of quaternized trihydroxyalkylamines or choline derivatives; and
U.S. Pat. No. 5,342,530 to Aften et al. which teaches the use of quaternary amine-based cationic polyelectrolyte and salt(s). The cation of the salt(s) may be a divalent salt cation, a choline cation, or certain N-substituted quaternary ammonium salt cations.
The use of quaternized polymers have one main advantage over the use of either potassium chloride or amine quaternary monomers in that they are able to provide substantially permanent clay stabilization. The structure of the polymers is such that there are several cationic sites available which are adsorbed simultaneously. Typically, these polymers contain anywhere from 400 to 7500 cationic sites. In order for the polymer to desorb from the clay, all of these cationic sites must simultaneously be displaced. The probability of these occurring is negligible, hence the substantially permanent nature of the treatment.
Prior art clay stabilizing systems are typically directed towards specific clay types. Applicant believes however that due to the heterogenous nature of many hydrocarbon bearing shale/clay formations, the specifically directed clay stabilizing systems are limited in their ability to effectively exchange with sodium ions in clay platelets other than in the formation for which they were designed and do not function in all clay types. Further, prior art products that have limited mobility when exposed to heterogeneous clay-type minerals inhibit their ability to effectively transport to the sites where they are needed. Some of the molecules described in the prior art will become adsorbed on the formation rock and therefore will not be available further back in the formation, such as during fracturing, limiting the resultant inflow because clay minerals encountered by the treatment fluid further from the well bore will be destabilized as the fluid will have lost most of the inhibitor molecules.
Many of the systems described in the prior art are pH sensitive and because they are typically single components, as the pH changes with dilution in the conate water and the like, the pH shifts to a pH at which the component can no longer work efficiently, if at all.
Clearly what is required is a clay stabilizer which is effective in all or substantially all of the clay constituents in a heterogeneous clay/shale formation. Preferably, the stabilizer is a single fluid additive which can be used alone or in combination with other wellbore fluids and which remains effective over a broad pH range.